Method of determining reservoir pressure

ABSTRACT

A well test method for use in tight gas reservoirs prior to hydraulic fracture stimulation. The method can use injection of water using low-rate surface pumps into the reservoir below parting pressure. The measured rates and pressures are converted to sandface rate and pressure datasets for each stage. The technique can utilize either surface or bottom-hole pressure sensors. The resulting sandface datasets are analyzed using the baseline/calibration method or other analysis appropriate to stage data to determine reservoir flow properties. The small-volume, staged well test enables estimation of the flow properties of reservoir, including pressure and permeability, in hours rather than days.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part under 35 U.S.C. §120 of pending U.S. patent application Ser. No. 13/327,182, filed Dec. 15, 2011, entitled “Method of Determining Reservoir Pressure,” which claims priority from U.S. Provisional Application Ser. No. 61/423,692, filed Dec. 16, 2010. The disclosures of said applications are hereby incorporated herein by reference in their entireties.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

1. Field of the Invention

This invention relates generally to the field of exploration and production of hydrocarbons. More specifically, the invention relates to a method of determining reservoir properties in hydrocarbon reservoirs.

2. Background of the Invention

Increasingly, hydrocarbon resource is being developed in low permeability reservoirs. For example, more than 50% of the currently identified gas resources in the United States is found within tight gas and shale gas reservoirs (ref. Table 9.2 of the US EIA report titled “Assumptions to Annual Energy Outlook 2011” http://38.96.246.204/forecasts/aeo/assumptions/pdf/0554(2011).pdf). Estimation of reservoir flow properties, including reservoir pressure and transmissibility in tight gas, shale gas and tight oil reservoirs is important for a variety of reasons including estimates for ultimate recovery, production forecasting and optimization of depletion planning. Completion designs, modeling studies and future field development decisions are all improved with better knowledge of current and historical reservoir pressures. However, reservoir flow properties are difficult to determine in low permeability reservoirs using current well testing methods due to the long shut-in times required for the well test to obtain reliable values. Injection testing during the completion phase performed prior to hydraulic fracturing in many cases has proven effective in determining reservoir flow properties in low permeability reservoirs. These types of tests become less economically attractive to run if reservoir conditions are such that the fluid level within the wellbore drops below surface resulting in the well going on vacuum before sufficient data has had time to be collected. Running downhole pressure gauges is often not economically practical. In addition, as the permeability decreases, the monitoring time required increases, introducing a significant delay in the well completion. Obtaining reservoir flow properties in a more economical manner has value in a number of ways. In marginally economic developments, it may present the only way to directly measure reservoir pressure and transmissibility. Mini falloff tests (MFoT) are the current accepted industry practice to obtain estimates of reservoir flow properties in low permeability reservoirs. While MFoTs are generally conducted prior to hydraulic fracture treatments the time to obtain analyzable data could still require several days thus limiting the application of this method on a wide scale basis. The main reasons for this are wellbore storage and the need to obtain pseudo radial flow. Having a method where wellbore storage and obtaining radial flow were not limiting factors would greatly enhance the ability to obtain estimates of reservoir flow properties. Should an MFoT be performed, having a prior independent estimate of reservoir pressure would allow for both a confirmation of reservoir pressure and improvements in permeability height and transmissibility estimates. If reservoir pressure and permeability are known then during production, rate transient analysis (RTA) can be more accurately applied to estimate fracture length and conductivity, thus allowing for improved understanding of completion efficiencies. Utilizing test results to establish relationships between reservoir pressure (pore pressure) and fracture and/or closure pressures within specific reservoir intervals, could potentially allow for using historically recorded fracture and/or closure pressures to provide estimates of historical field wide depletion. Documented results utilizing Eaton's correlation shows that comparing measured pore pressure to fracture and/or closure pressure could result in establishing trend lines for specific reservoirs. Applying previously documented fracture and/or closure pressures to these trend line relationships would yield estimated reservoir pressure at the time of each of the prior fracture simulations, thus providing estimates of historical fieldwide depletion. Establishing and utilizing these trend lines then could greatly leverage the test results far beyond the limited amount of actual test data actually measured. To have confidence in these trend lines a statistically meaningful set of measures reservoirs pressures must be taken.

Consequently, there is a need for an improved low-cost and accurate method of determining reservoir pressure in low permeability reservoir systems.

BRIEF SUMMARY

These and other needs in the art are addressed in one embodiment by a method of determining reservoir pressure in a gas well. Embodiments of the method have application in different type of gas reservoirs, but are primarily targeted for use in tight gas and shale reservoirs (e.g. low permeability gas reservoir systems). It is however recognized that the method also may be used in conventional reservoirs (both gas and oil), tight oil, shale oil and coalbed methane reservoirs. In an embodiment, the method initially includes performing a series of injection events with discrete stages, determining the rate and pressure at the sandface to generate one or more pairs of baseline and calibration trends. The technique may be implemented utilizing either bottom-hole gauges, surface gauges or level gauges with properly designed and instrumented surface or downhole injection pumps. The baseline and calibration trends match at a particular value of reservoir pressure, generating a distinguishable estimate of reservoir pressure. When more than one pair is generated, the method provides information that may be used to correct for the supercharging of the porous media next to the well imposed by the injection test.

In an embodiment, the method for estimating reservoir pressure may be applied to a new isolated set of perforations that have had little or no production. A small amount of fluid may injected to ensure perforations are open, but careful measurement of volumes pumped and injection rates/volumes are limited to minimize the creation of any hydraulic fracture length during the test. Several different methods of injecting fluid and acquiring the datasets may be utilized. In all embodiments, a discrete shift in either rate or pressure or both is imposed to generate a baseline and calibration trend pair. Bottom hole injection pressure and injection rates at the sandface are obtained for one or more pairs of baseline and calibration trends. The number of baseline and calibration pairs is one less than the number of stages generated.

In an embodiment, a method of determining reservoir pressure from a reservoir comprises injecting a fluid into a well drilled into the reservoir. The method comprises measuring one or more parameters indicative of reservoir pressure over a period time to form a baseline dataset, wherein the one or more parameters include at least bottom hole pressure and volumetric flow rate. The method also comprises inducing a change in the injection rate or injection pressure of the fluid. In addition, the method comprises measuring the one or more parameters indicative of reservoir pressure for at least a second period of time to form a calibration dataset. The method further comprises estimating a reservoir pressure value. The method additionally comprises plotting the baseline dataset and the calibration datasets to form a baseline curve and calibration curve based upon the reservoir pressure value, and comparing the baseline curve and the calibration curve to determine if the reservoir pressure value is correct. If the baseline curve and the calibration curve are not aligned, then repeating the estimation and plotting until the baseline curve and the calibration curve are aligned.

In another embodiment, a method of determining reservoir pressure from a reservoir comprises injecting a fluid into the reservoir at a first rate or first pressure to measure one or more parameters indicative of reservoir pressure over a first time period to form a baseline dataset. The method also comprises injecting the fluid in the reservoir at a different rate or different pressure than the first rate or first pressure to measure one or more parameters indicative of reservoir pressure over a time period to form one or more calibration datasets. In addition, the method comprises using a form of Darcy's flow equation to compare the baseline datasets and the one or more calibration datasets to determine reservoir pressure.

In an embodiment, a system for determining reservoir pressure comprises one or more sensors positioned to measure one or more parameters indicative of reservoir pressure from a hydrocarbon producing reservoir. The one or more parameters include at least bottom hole pressure and volumetric flow rate. The system includes an interface coupled to one or more sensors for receiving the one or more parameters from the one or more sensors. In addition, the system comprises a memory resource, an input and output functions for presenting and receiving communication signals to and from a human user, one or more central processing units for executing program instructions, and program memory coupled to the central processing unit for storing a computer program including program instructions that when executed by the one or more central processing units cause the computer system to perform a plurality of operations for determining reservoir pressure. The plurality of operations comprises forming a baseline dataset based on the one or more parameters. The operations also comprise forming one or more calibration datasets based on the one or more parameters. Moreover, the operations comprise estimating a reservoir pressure value. The operations additionally comprise plotting the baseline dataset and the calibration datasets to form a baseline curve and calibration curve based upon the reservoir pressure value. Furthermore, the operations comprise comparing the baseline curve and the calibration curve to determine if the reservoir pressure value is correct and if the baseline curve and the calibration curve are not aligned, then repeating (c) through (e) until the baseline curve and the calibration curve are aligned.

The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of the invention, reference will now be made to the accompanying drawings in which:

FIG. 1 illustrates a flowchart of an embodiment of the method;

FIG. 2 a illustrates a well configured for a falling fluid level test for use with an embodiment of the method;

FIG. 2 b illustrates a well configured for a constant pressure or constant rate injection test for use with an embodiment of the method;

FIG. 2 c illustrates a well configured for a wireline deployed injection test for use with an embodiment of the method;

FIG. 2 d illustrates a well configured for a coiled tubing deployed injection test for use with an embodiment of the method;

FIG. 2 e illustrates a well configured for a wireline deployed injection test for use with an embodiment of the method;

FIG. 2 f illustrates a well configured for a coiled tubing deployed injection test for use with an embodiment of the method;

FIG. 3 illustrates a computer system for employing the method;

FIG. 4 a is an example of a plot of a baseline curve and a calibration curve where the estimated reservoir pressure value is too low;

FIG. 4 b is an example of a plot of a baseline curve and a calibration curve where the estimated reservoir pressure value is too high;

FIG. 4 c is an example of a plot of a baseline curve and a calibration curve where the estimated reservoir pressure value is too low;

FIG. 4 d is an example of a plot of a baseline curve and a calibration curve where the estimated reservoir pressure value is too high;

FIG. 4 e is an example of a plot of a baseline curve and a calibration curve where the estimated reservoir pressure value is correct;

FIG. 5 illustrates an example of a plot of a baseline curve and a calibration curve where the estimated reservoir pressure value is correct including incorporation of the optional method to correct for supercharging;

FIGS. 6 a and 6 b illustrate alternate plotting approaches of the data obtained through the described testing techniques to obtain reservoir pressure;

FIG. 7 illustrates a flowchart of an embodiment of a method for determining reservoir flow properties;

FIG. 8 shows an example of staged testing of a well in accordance with various embodiments; and

FIG. 9 shows conversion of the raw data acquired in FIG. 8 to sandface rate and pressure in accordance with various embodiments.

NOTATION AND NOMENCLATURE

Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 is a flowchart depicting an embodiment of a method for determining reservoir pressure. In an embodiment, the method preferably is applied to wells with a new isolated set of perforations 118 in a well has not begun hydrocarbon production. More particularly, fluid may be injected into the well and into the formation 119 in block 10, preferably prior to fracturing or other injection of material into the reservoir. However, it is envisioned that fluid may be injected at any time during the completion or production process into the reservoir. In one embodiment, the fluid injection rate may be limited to injection rates/volumes which minimize the creation of any hydraulic fracture length during the test. The fluid may be any suitable fluid such as without limitation, saline fluid, water, potassium chloride fluid, ionic fluid, non-ionic fluid, or combinations thereof. Gaseous fluids could also be used. All embodiments of the method include injection stages generated by discrete shifts or changes in either rate or pressure or both and generate timed cumulative volume and pressure data.

Referring to FIG. 1, in some embodiments, prior to block 10, it is necessary to establish the test correction parameters of the casing before perforation or above the open hole section. In addition to the length and inner diameter, an estimate is needed of the magnitude of the correction factors needed to convert from surface volumes to sandface volumes. One factor of universal concern is the level of weepage of liquid through the casing threads. Ballooning of the casing as the result of internal pressurization will affect the estimation of sandface volumes. Another factor may be heat transfer into the wellbore as cooler fluids are injected, resulting in a thermal expansion. These estimates can be generated by those skilled in the art through calculation, observation of the mechanical integrity test of the well to be tested, inference based on performance of offset wells of similar construction, or engineering judgment.

Still referring to FIG. 1 in block 12, fluid such as a water phase is injected with a low flow rate in to the gas reservoir. Examples of methods to inject the fluid include the constant pressure injection test (CPIT) or constant rate injection test (CRIT) in which fluid may be pumped in or in falling fluid level tests (FFLT) fluid flows in to the reservoir due to weight of hydrostatic pressure, i.e., where hydrostatic pressure is higher than reservoir pressure. Further examples of injection test are described in more detail below. The initial or first injection rate is dependent on reservoir properties (e.g. permeability, reservoir pressure) and wellbore completion design (e.g. casing inner diameter, perforation height). For example, results from a reservoir simulation study utilizing the CPIT method for a three day injection test (i.e., two days for baseline and one day calibration), results determined by reservoir simulation studies shows that for a reservoir with 0.01 md, perforation height of 30′, 20 shots per foot and 4000 psig reservoir pressure injection rates may range from 0.12 bbls/day to about 3.6 bbls/day for injection pressures ranges of 4500 to 5500 psig. Time periods for these types of injection test depend on permeability and other specifics to the particular well being tested. Volume and pressure data is recorded over a time period in block 12.

Now referring to FIG. 1, the injection rate and/or pressure may then be changed to a different injection rate or injection pressure in block 13 to obtain a calibration data set in block 15. A calibration dataset is acquired in the FFLT embodiment by refilling the casing with a different volume of fluid.

Still referring to FIG. 1, the data collection in 15 can be completed at this point without gathering data for a supercharging correction. If a supercharging correction is desired, return to block 13 to generate another calibration data set. The prior calibration data set serves as the baseline data set for this pair. As many pairs of baseline/calibration data may be gathered as desired, but at least 2 calibration datasets (3 stages) may be used for the supercharging correction and alternatively, more than 4 calibration datasets (5 total stages) may be used.

Still referring to FIG. 1, in 16, once the field data is collected, the datasets may be corrected to sandface conditions. The baseline/calibration analysis is based on the cumulative volume, rate and pressure at the sandface. The various test methods may not directly observe these values and it may be necessary to correct the observation to sandface conditions. All the volume or flow measurements are subject to correction for temperature and pressure, for thread weepage and, thermal changes in the wellbore during the test, among others. Generally, these corrections are established by a number of special mechanical integrity tests on the uncompleted casing. All the pressure measurements are subject to correction for depth; for instance, a surface pressure observation is corrected to the sandface datum by the true vertical depth and the fluid gradient. In cases such as recompletions where tubing and packer systems are utilized, mechanical integrity testing of those systems would be appropriate prior to performing the injection test.

On volumetric or flowrate data, corrections may include but are not limited to the effects of temperature and pressure, the weepage rate of the casing, the ballooning effect of the casing, the thermal expansion driven by the introduction of cooler fluids into a hotter geothermal gradient, and any other effects peculiar to the particular well construction. On pressure data, the bottom hole pressure at the sandface may be calculated using the difference in true vertical depth between the measurement gauge and the sandface and the fluid gradient established by reference, experience or experimentation.

Still referring to FIG. 1, in block 18, once pairs of baseline and calibration volume and pressure dataset are corrected to sandface conditions are available, analysis of the data can be done as described below.

Without being limited by theory, the principle behind the analysis is based upon Darcy's equation. Darcy's equation for radial flow is shown below:

$q = {\frac{2\pi \; {kh}}{\mu}\frac{P_{bh} - P_{res}}{{\ln \left( \frac{r_{e}}{r_{w}} \right)} + S}}$

Where q is the volumetric flow rate, μ is the dynamic viscosity, P_(bh) is measured bottom hole pressure, P_(res) is the reservoir pressure, r_(e) is the radius of invasion, r_(w), is the wellbore radius, h is perforation height, k is reservoir permeability, and S is a skin factor.

Darcy's radial flow equation may be re-arranged as follows:

${\ln \left( \frac{r_{e}}{r_{w}} \right)} = {{\frac{2\pi \; {kh}}{\mu}\frac{P_{bh} - P_{res}}{q}} - S}$

Assuming radial flow has been achieved, plotting ln (re/rw) vs ΔP/q will yield a straight line with slope of 2πkh/μ, and y intercept of −S. Due to varying flow regimes and other factors straight lines may or may not be observed when plotting actual test data. Findings from field tests and numerical modeling efforts have shown that achieving radial flow to establish straight line relationships may not have to be used to determine reasonable estimates of reservoir pressure using the proposed injection test method. The basic reason behind this is that variations in estimates of reservoir pressure when performing the iteration process provides enough distinction even with relative small variations to establish observable trends and analyzable movements between injective relationship (i.e., ΔP/q) at each injection stage. This sensitivity to reservoir pressure allows for the ability to match ΔP/q relationships within each stage where trends can be used instead of straight lines, if needed. In another embodiment of the analysis, re/rw can be generally represented by the cumulative volume injected. This approximation may be applied since most of the terms related to re/rw are constant with the exception of the cumulative fluid injected. The volume injected (Wi) can be expressed volumetrically as Wi=[Ø(1-Sw irr) h π(re²−rw²)/Bw, where all of these terms are relatively constant with the exception of re. Therefore re is proportional to Wi. The wellbore radius is rw and is considered to be constant, thus ln (Wi) can be used as a surrogate for ln (re/rw).

An initial guess of the reservoir pressure is made in block 17. The lognormal of the cumulative fluid injection (ln(Qi)) versus pressure drop divided by flow rate (ΔP/q) is then plotted in block 18. ΔP is the injection pressure at the sandface minus the assumed or estimated reservoir pressure.

If the estimation (guess) of reservoir pressure is correct, then the baseline and calibration trends, plots, or curve will match or be aligned. See FIG. 5. If the assumed reservoir pressure is too high, the baseline trend will be to the left of the calibration trend and the estimate should be lowered. Conversely, if the assumed pressure is too low, the baseline trend will be to the right of the calibration trend. Estimates of reservoir pressure are repeated until the trends or curves are matched or aligned in block 19. These operations may be performed manually or automatically by a system such as described below and in FIG. 3.

The plotting approach described above allows for a linear relationships between the variables plotted as described by Darcy's radial flow equation, however other variables can be plotted or analyzed to determine reservoir pressure. FIGS. 6 a and 6 b for example shows two such alternate approaches for data analysis. The first plot shown has flow rates in FIG. 6 a is normalized by delta P of injection verses cumulative injection volumes. Offsets between the baseline data and the calibration data in the case over or under estimation of the reservoir pressure are observed, thus still allowing for determination of reservoir pressure. The second plot in FIG. 6 b has natural log of r_(e)/r_(w) versus delta pressure over rate. This is similar to the plotting method shown in FIG. 5.

The method relies on the observation, both from actual field data as well as numerical simulation, that the value at which the baseline and calibration trends match is approximately the current pressure in the reservoir near the wellbore. The analysis is completed by plotting sandface pressure and rate data in a specialized form from terms arranged in Darcy's flow equation. A reservoir pressure is assumed, and the baseline and calibration trends are examined for a match. If the baseline trend is left of the calibration trend, the assumed pressure is too high and the next estimate should be lower. If the baseline trend is right of the calibration trend, the estimate should be higher. Accurate estimates of the reservoir pressure are obtained in a few iterations. Darcy's equation for radial flow has been primarily used for this method, however other forms of Darcy's equations may be considered for better matches depending on the geometry, for example spherical around perforations, radial around open hole completions, and linear for fractures, among others. As cumulative injection progresses during a test protocol, it is possible that the flow regime will change, and from a practical standpoint, the volume of rock being sensed may change. Thus, the method can still be used to determine an approximation of reservoir pressure using Darcy's equation for radial flow during these early non-radial flow periods, however the plot will not be a pure linearly relationship. Each pair of stages generated by the test protocol will generate a discrete estimate of the pressure present in the reservoir according to the injectivity matches from one injection stage to the next.

Referring still to FIG. 1, if more than one baseline/calibration pair is collected, a correction may be performed to account for supercharging. Based on observations of both actual field data as well as numerical simulation, it has been observed that the pressure estimate increases with each stage of the test. Since fluids are being injected, the pressure near the sandface is generally increasing; an effect which may be referred to as “supercharging”. Minimizing the volume injected into the formation, while still providing sandface volume and pressure values with acceptable signal/noise ratio, may reduce the effect of supercharging. However, in most cases it is advantageous to determine the degree of supercharging present and account for it. For a given test protocol with roughly equivalent stage durations, the degree of supercharging is proportional to the cumulative fluid volume injected during the test. The trend of the discrete pressure estimates from multiple baseline/calibration pairs can be extrapolated back to zero cumulative injection to arrive at the best possible estimate of the reservoir pressure at that point in time. The pressure estimates obtained for each pair may be plotted against the cumulative volume of fluid injected at sandface conditions and will describe an increasing trend demonstrating the magnitude of supercharging. An extrapolation may then be performed to arrive at the final reservoir pressure estimate Pr.

Other methods of accounting for supercharging may entail more classical pressure transient techniques of applying the diffusivity or other methods to more rigorously account for buildup and dissipation of supercharge pressures as they relates to injection and reservoir parameters over time.

Any suitable method and/or system may be used to obtain data or information for use with the disclosed reservoir pressure determination methods. More particularly, any suitable method or system may be used to inject the fluid in block 10 and measure rate and/or time in blocks 12 and 15. FIG. 2 a illustrates an embodiment of a well for implementing a falling fluid level test (FFLT) for acquiring reservoir pressure data. In the FFLT, the injected fluid at the sandface is calculated by either observing or sensing the level in the tubing (for example, but not limited to an acoustic level sensor) or by using a bottom hole pressure gauge and the density of the fluid to calculate the level. Since the inside diameter of the casing is known the volume of fluid injected over time (e.g. rate) can be determined. In addition, the pressure at the sandface is determined by either direct observation by the bottom hole pressure gauge or by using the level and the density of the fluid to calculate sandface pressure. Stages are generated by adding liquid to the tubing.

FIG. 2 a depicts a typical well 110 configured for FFLT. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. During injection the fluid level 125 will decrease and fluid will leave the well 110 through perforations 118 and enter the formation 119. FIG. 2 a shows a well 110 with a first formation 119. Although the FIGS. 2 a-2 d do not illustrate production or drilling tubing, it is envisioned that any embodiment of the described methods or systems may be used with wells having production or drilling tubing or without. Other components of a well are not shown and are well known in the art. In embodiments, one or more downhole pressure sensors 140 may be disposed above or below the perforations 118 including a surface location. The pressure sensor 140 may be any device known to those of skill in the art for measuring pressure. For example, the pressure sensors may comprise without limitation, pressure gauges, pressure transducers, pressure transmitters, pressure senders, pressure indicators and piezometers, manometers, or combinations thereof.

In embodiments, one or more level sensors 141 or 142 may be disposed at or above the fluid level in the well. The level sensor 141 or 142 may be any device known to those of skill in the art for measuring level. For example, the level sensors may comprise without limitation, sonic detection, radar detection, capacitance, density, thermal, floats and displacement, or combinations thereof.

In one embodiment, the FFLT method utilizes measurements from pressure sensor 140. In this case, the injected fluid is calculated by observing the change in bottom hole pressure at the gauge over time and using the known density of the fluid to determine the changing fluid level over time. Since the inside diameter of the casing is know the volume of fluid injected over time (e.g. volumetric rate) can be determined.

The FFLT method may also utilize level sensors 141 or 142 (e.g. an acoustic level sensor such as one commercially manufactured by Echometer™, Wichita Falls, Tex.) located at or above the liquid level. In this case, the injected fluid is calculated by observing the change in fluid level over time using the known inner diameter of the casing. The pressure at the sandface is calculated by the known pressure gradient of the fluid in the well.

FIG. 2 b illustrates an embodiment of a system for a constant pressure injection test (CPIT) or constant rate injection test (CRIT). CPIT and CRIT methods utilize one or more small surface pumps that are instrumented to accurately measure injected volumes while maintaining constant pressure or accurately measure pressure while maintaining constant volume, respectively. Stages are generated by applying a new setpoint to the controller. The FPT (Falling Pressure Test) is another method of applying this technique. A FPT utilizes the known volume and compressibility within the wellbore in conjunction with changes in surface or bottom-hole measured pressures to calculate fluid volumes entering the reservoir from the wellbore over time. The FPT may be applied in tight and/or over pressured reservoirs where a liquid column can be reasonably maintained during the test. Stages are generated by re-pressurizing the system.

FIG. 2 b depicts a typical well 110 configured for the CPIT, CRIT or FPT test. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. During injection fluid may leave the well 110 through perforations 118 and enter the formation 119. FIG. 1 b shows a well 110 with a first formation 119. Other components of a well are not shown and are well known in the art.

In such an embodiment, fluid may be pumped into the well from the surface using a metering pump 150. All of these methods utilizes one or more small surface pumps 150 that are adapted to accurately measure injected volumes while maintaining either constant pressure or constant rate (e.g., within design specs of pumping system). The surface metering pump 150 may be any suitable pump known to those of skill in the art including without limitation, piston pumps, diaphragm pumps, reciprocating pumps, rotary pumps, progressing cavity pumps, or combinations thereof. Alternatively, it may include use of a non-metering pump 150 and one or more meters 160.

FIG. 2 c illustrates an embodiment of the method for a wireline downhole injection test (WDIT). WDIT may be applicable when a low signal/noise ratio is obtained due to the effects of the large casing volume, including but not limited to thread weepage and heat transfer resulting in thermal expansion or contraction. In this test, the downhole pump and pressure gauge are deployed by wireline along with a resettable plug and then a CPIT, CRIT and/or FPT may be performed. The device could be installed underneath perforating guns. FIG. 2 c depicts a typical well 110 configured for a WDIT test. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. The downhole assembly 183 is deployed on wireline 170 and set in position above the perforations 118. The downhole pump 186 injects fluid obtained above the plug into the formation 119 while the pressure gauge 185 measures the pressure. FIG. 1 c shows a well 110 with a first formation 119. Other components of a well are not shown and are well known in the art.

In another embodiment, referring to FIG. 2 c, the corrections necessary to obtain sandface volume and pressure may be reduced by placing the downhole pump 186 and the pressure gauge 185 on a downhole assembly 183 with a resettable packing 187 to seal the casing. The metering pump 186 can then draw fluid from above the downhole assembly 183 and inject it into the formation 119 while recording timed volume with the pressure gauge 185 recording timed pressure. The wireline 170 can be either electric line or slickline; in the case of slickline the downhole assembly 170 includes a power storage device such as batteries and a logic controller. This downhole assembly 183 could be deployed in conjunction with perforating guns to allow immediate testing of a zone upon perforation. The CPIT, CRIT or FPT protocols can then be applied and data with greater signal/noise ratio may be obtained.

FIG. 2 d illustrates an embodiment of the method for a coiled tubing downhole injection test (CDIT). CDIT may be applicable to low signal/noise situations introduced by casing conditions. In this test, the pressure gauge is installed on a resettable packer deployed by coiled tubing with a pressure gauge. A CPIT, CRIT and/or FPT are then performed using a surface pump.

FIG. 2 d depicts a typical well 110 configured for CDIT. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. The downhole assembly 193 is deployed on coiled tubing 190 and set in position above the perforations 118. The surface pump 191 injects fluid into the formation 119 while the pressure gauge 195 measures the pressure. FIG. 1 d shows a well 110 with a first formation 119. Other components of a well are not shown and are well known in the art.

Still referring to FIG. 2 d, the corrections necessary to obtain sandface volume and pressure may be reduced by using coiled tubing 190 to carry the injected fluid from a surface metering pump 191. The downhole assembly 193, including the pressure gauge 195, can be lowered on coiled tubing 190 and the packing 197 set above the perforations 118 and formation 119 of interest. The CPIT, CRIT or FPT protocols can then be applied and data with greater signal/noise ratio may be obtained.

Reservoir pressure and other flow properties including transmissibility are difficult to determine in low permeability reservoirs using conventional well testing methods due to the long shut-in times required for the well test to obtain a reliable estimate of reservoir properties. Embodiments of the multi-stage method of testing a gas well disclosed herein overcome the deficiencies of conventional methods. Embodiments of the method have application in different types of gas reservoirs, but are primarily targeted for use in tight gas and shale reservoirs (e.g. low permeability gas reservoir systems). It is however recognized that embodiments also may be used in conventional reservoirs (both gas and oil), tight oil and shale oil reservoirs. In some embodiments, the method initially includes performing a series of low volume injection and/or production events with discrete stages, followed by conversion of the observed data to sandface rate and pressure. The technique may be implemented utilizing either bottom-hole gauges, surface gauges or level gauges with properly designed and instrumented low-rate surface injection pumps.

In other embodiments, the method for estimating reservoir flow properties is applied to a new isolated set of perforations that have had little or no production. A small amount of fluid may injected to ensure perforations are open, but careful measurement of volumes pumped and injection rates/volumes are limited to minimize the creation of any hydraulic fracture length during the test. Several different methods of injecting fluid and acquiring the datasets may be utilized, with the appropriate conversion made to obtain sandface rate and pressure.

FIG. 7 is a flowchart depicting an embodiment of a method for staged pre-stimulation well testing. Performance of the method pre-stimulation refers to execution of the method prior to application of production enhancement treatments, such as hydraulic fracturing. In an embodiment, the method preferably is applied to wells with a new isolated set of perforations 118 in a well has not begun hydrocarbon production. More particularly, fluid may be injected into the well and into the formation 119 in block 710, preferably prior to fracturing or other injection of material into the reservoir. In addition, fluid may be produced from the formation into the wellbore. In one embodiment, the fluid injection rate may be limited to injection rates or volumes which prevent the creation of any hydraulic fracture length during the test. The fluid may be any suitable fluid such as without limitation, saline fluid, water, potassium chloride fluid, ionic fluid, non-ionic fluid, or combinations thereof. Gaseous fluids could also be used. All embodiments of the method include injection stages generated by discrete shifts or changes in either rate or pressure or both and generate timed cumulative volume and pressure data. Each of the stages may be relatively short. For example, in some embodiments, some stages may be no more than 30 minutes in length. In some embodiments, some stages may be not more than 10 minutes in length. The cumulative length of all stages executed in a test may be no more than 12 hours in some embodiments. The volume of liquid injected during a stage may also be relatively low. For example, in some embodiments, no more than 40 gallons of liquid may be injected in a testing stage. In some embodiments, no more than 10 gallons of liquid may be injected in a stage. In some embodiments, the pressure in the formation may be greater than the pressure in the wellbore, in which case the reservoir will produce into the wellbore, causing the wellbore pressure or level to rise. When the volumes are small, this production is exclusively water from the invaded zone.

Referring to FIG. 7, in some embodiments, prior to block 710, the test correction parameters of the casing may be established before perforation or above the open hole section. In addition to the length and inner diameter, an estimate is needed of the magnitude of the correction factors needed to convert from surface volumes to sandface volumes. One factor of concern is the level of weepage of liquid through the casing threads. Ballooning of the casing as the result of internal pressurization will affect the estimation of sandface volumes. Another factor may be heat transfer into the wellbore as cooler fluids are injected, resulting in a thermal expansion. These estimates can be generated by those skilled in the art through calculation, observation of the mechanical integrity test of the well to be tested, inference based on performance of offset wells of similar construction, or engineering judgment.

Still referring to FIG. 7 in block 712, fluid such as a water phase is injected with a low flow rate in to the gas reservoir. Examples of methods to inject the fluid include the falling pressure test (FPT), the constant pressure injection test (CPIT) or constant rate injection test (CRIT) in which fluid may be pumped in or in falling fluid level tests (FFLT) fluid flows in to the reservoir due to weight of hydrostatic pressure, i.e., where hydrostatic pressure is higher than reservoir pressure. Further examples of injection tests are described in more detail below. The initial or first injection rate is dependent on reservoir properties (e.g. permeability, reservoir pressure) and wellbore completion design (e.g. casing inner diameter, perforation height). Time periods for these types of injection tests depend on permeability and other specifics to the particular well being tested. Surface volume and pressure data is recorded over a time period in block 712.

Referring again to FIG. 7, the injection rate and/or pressure may then be changed to a different injection rate or injection pressure in block 713 to obtain a subsequent stage data set in block 715. A subsequent dataset is acquired in the FFLT embodiment by refilling the casing with a different volume of fluid or by pressurizing with a gas.

Still referring to FIG. 7, the data collection in 715 can be completed at this point if the well characteristics and analysis method warrant, or, if well characteristics and the analysis method warrant, additional stage datasets may be collected per block 716.

Still referring to FIG. 7, in 717, once the field data is collected, the datasets may be corrected to sandface conditions. The resulting sandface datasets are analyzed using the baseline/calibration method or other analysis appropriate to stage data to determine reservoir flow properties. All of the staged test analysis methods, such as the baseline/calibration method, are based on the cumulative volume, rate and pressure at the sandface. The various test methods may not directly observe these values and it may be necessary to correct the observation to sandface conditions.

All the pressure measurements are subject to correction for depth and hydrostatics. On pressure data, the bottom hole pressure at the sandface may be calculated using the difference in true vertical depth between the measurement gauge and the sandface and the fluid gradient established by reference, experience or experimentation.

On volumetric or flowrate data, the most significant correction to obtain sandface rate and volume is the wellbore modulus in the case of liquid-full wellbores and the liquid level in the case of wellbores that are not liquid-filled. The wellbore modulus is the pressure change in the wellbore at any point when a unit volume of liquid is injected or removed. It is calculated from the compressibility of the liquid in the wellbore and the volume of the wellbore in the simplest case. For wellbores that have a liquid level, the sandface rate and volume in the simplest case is calculated from the wellbore specific volume, which is the volume per unit length. Corrections may include but are not limited to the ballooning effect of the casing, the effects of temperature and pressure, the weepage rate of the casing, the thermal expansion driven by the introduction of cooler fluids into a hotter geothermal gradient, and any other effects peculiar to the particular well construction. Generally, these corrections are established by a number of special mechanical integrity tests on the uncompleted casing. In cases, such as recompletions, where tubing and packer systems are utilized mechanical integrity testing of those systems would be appropriate prior to performing the injection test.

The corrections applied for the accurate determination of the rate and pressure at the sandface may depend on the location of the pressure measurement and the method of measuring volumes added to or removed from the wellbore. One example involves isothermal water in a wellbore that is perfectly rigid and hermetically sealed except for the access at the sandface and at the surface, which is generally adequate to generate values of sufficient precision to permit analysis. However, if necessary, the error introduced by the assumption of a perfectly rigid wellbore may be corrected by including hoop strain in the calculation of the wellbore bulk modulus. The error associated with thread weepage may be corrected by measuring the leakage coefficient during the initial well pressure testing. The error due to thermal expansion of liquids may be reduced by more complex calculations using the geothermal gradient and the heat transfer coefficient.

For simplicity, embodiments may assume that the gas column has zero hydrostatic head. For the case of pressure measurement p_(st) at the surface on a wellbore with the sandface at a true vertical depth D_(R) and a liquid level D_(Lt) of water, the sandface pressure is:

p _(wst) =p _(st)+[(D _(R) −D _(Lt))*g _(W)]

where: p_(wst) is pressure at the sandface at any time t, m/Lt², psia; p_(st) is pressure at the surface at any time t, m/Lt², psia; D_(R) is true vertical depth of the sandface, L, feet; D_(Lt) is liquid level in the casing measured from the surface at any time t, L, feet, and g_(w) is water hydrostatic gradient at average temperature, m/t2, psid/ft.

In the case of a water-filled wellbore the calculation reduces to:

p _(wst) =p _(st) +D _(R) *g _(W)

The sandface rate may be calculated from the observed liquid level by:

$q = \frac{\left\lbrack {S_{c}*\left( {D_{{Lt}\; 2} - D_{{Lt}\; 1}} \right)} \right\rbrack}{\left( {t_{2} - t_{1}} \right)}$

where: q is sandface rate, L³/t, BBL/d; S_(c) is volumetric capacity of casing, L², BBL/ft; D_(Lt2) is liquid level in the casing at t₂, L, feet; D_(LT1) is liquid level in the casing at t₁, L, feet; and t is time, t, days.

The wellbore bulk modulus is calculated from the compressibility of water and the volume of wellbore. The sandface rate during a stage initiated by an instantaneous impulse on a water-filled wellbore may be calculated from the change in surface pressure using the wellbore bulk modulus K_(wb):

$q = \frac{\left( {p_{{st}\; 2} - p_{{st}\; 1}} \right)}{\left\lbrack {K_{wb}*42*\left( {t_{2} - t_{1}} \right)} \right\rbrack}$

where: K_(wb) is bulk modulus, wellbore, m/L⁴t², psi/gallon.

Any suitable method and/or system may be used to obtain data or information for use with the disclosed reservoir pressure determination methods. More particularly, any suitable method or system may be used to inject the fluid in blocks 710 and 713 and measure rate and/or time in blocks 712 and 715. FIG. 2 a illustrates an embodiment of a well for implementing a falling fluid level test (FFLT) for acquiring stage datasets. In the FFLT, the injected fluid at the sandface is calculated by either observing the level in the tubing (for example, but not limited to, an Echometer™) or by using a bottom hole pressure gauge and the density of the fluid to calculate the level. Since the inside diameter of the casing is known the volume of fluid injected over time (e.g. rate) can be determined. In addition, the pressure at the sandface is determined by either direct observation by the bottom hole pressure gauge or by using the level and the density of the fluid to calculate sandface pressure. Stages may be executed by pressurizing the space above the level with a gas or by adding liquid to the wellbore.

FIG. 2 a depicts a typical well 110 configured for FFLT. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. During injection fluid levels will decrease as shown at 125 and fluid will leave the well 110 through perforations 118 and enter the formation 119. FIG. 2 a shows a well 110 with a first formation 119. Although the FIGS. 2 a-2 f do not illustrate production or drilling tubing, it is envisioned that any embodiment of the described methods or systems may be used with wells having production or drilling tubing or without. Other components of a well are not shown and are well known in the art. In embodiments, one or more downhole pressure sensors 140 may be disposed above or below the perforations 118, including at a surface location. The pressure sensor 140 may be any device known to those of skill in the art for measuring pressure. For example, the pressure sensors may comprise without limitation, pressure gauges, pressure transducers, pressure transmitters, pressure senders, pressure indicators and piezometers, manometers, or combinations thereof.

In embodiments, one or more level sensors 141 or 142 may be disposed at or above the fluid level in the well. The level sensor 141 or 142 may be any device known to those of skill in the art for measuring fluid level. For example, the level sensors may comprise without limitation, gas volume calculation from gas law, sonic detection, radar detection, capacitance, density, thermal, floats and displacement, or combinations thereof.

In one embodiment, the FFLT method utilizes measurements from pressure sensor 140. In this case, the injected fluid is calculated by observing the change in bottom hole pressure at the gauge over time and using the known density of the fluid to determining the changing fluid level over time. Since the inside diameter of the casing is know the volume of fluid injected over time (e.g. volumetric rate) can be determined.

The FFLT method may also utilize level sensors 141 or 142 (e.g., sonic) located at or above the liquid level. In this case, the injected fluid is calculated by observing the change in fluid level over time using the known inner diameter of the casing. The pressure at the sandface is calculated by the known pressure gradient of the fluid in the well.

FIG. 2 b illustrates an embodiment of a system for a constant pressure injection test (CPIT), constant rate injection test (CRIT) or falling pressure test (FPT). CPIT and CRIT methods utilize one or more small surface pumps that are instrumented to accurately measure injected volumes while maintaining constant pressure or accurately measure pressure while maintaining constant volume, respectively. Stages are generated by applying a new setpoint to a controller that controls injection rate or pressure (e.g., via a pump 150). The FPT method uses a simple low rate surface pump to pressurize the wellbore to initiate a stage. A FPT utilizes the known volume and compressibility within the wellbore in conjunction with changes in surface or bottom-hole measured pressures to calculate fluid volumes entering the reservoir from the wellbore over time. The FPT may be applied in tight and/or over pressured reservoirs where a liquid column can be reasonably maintained during the test. Stages are generated by re-pressurizing the system.

FIG. 2 b depicts a typical well 110 configured for the CPIT, CRIT or FPT test. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. During injection fluid may leave the well 110 through perforations 118 and enter the formation 119. FIG. 2 b shows a well 110 with a first formation 119. Other components of a well are not shown and are well known in the art.

In such an embodiment, fluid may be pumped into the well from the surface using a pump 150. The CPIT and CRIT methods utilizes one or more small surface pumps 150 that are adapted to accurately measure injected volumes while maintaining either constant pressure or constant rate (e.g., within design specs of pumping system). For the FPT method, a simple pump may be used. The surface pump 150 may be any suitable pump known to those of skill in the art including without limitation, piston pumps, diaphragm pumps, reciprocating pumps, rotary pumps, progressing cavity pumps, or combinations thereof.

FIG. 2 e illustrates an embodiment of a system for a wireline downhole injection test (WDIT). WDIT may be applicable when a low signal/noise ratio is obtained due to the effects of the large casing volume, including but not limited to thread weepage and heat transfer resulting in thermal expansion or contraction. In this test, the downhole pump and pressure gauge are deployed by wireline along with a resettable plug and then a CPIT, CRIT and/or FPT may be performed. The device could be installed underneath perforating guns. FIG. 2 e depicts a typical well 110 configured for a WDIT test. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. The downhole assembly 183 is deployed on wireline 170 and set in position above the perforations 118. The downhole pump 186 injects fluid obtained above the plug into the formation 119 while the pressure gauge 185 measures the pressure. FIG. 2 e shows a well 110 with a first formation 119. Other components of a well are not shown and are well known in the art.

In another embodiment, referring to FIG. 2 e, the corrections necessary to obtain sandface volume and pressure may be reduced by placing the downhole pump 186 and the pressure gauge 185 on a downhole assembly 183 with a resettable packing 187 to seal the casing. The metering pump 186 can then draw fluid from above the downhole assembly 183 and inject it into the formation 119 while recording timed volume with the pressure gauge 185 recording timed pressure. The wireline 170 can be either electric line or slickline if the downhole assembly 170 includes a power storage device such as batteries and a logic controller. This downhole assembly 183 could be deployed in conjunction with perforating guns to allow immediate testing of a zone upon perforation. The CPIT, CRIT or FPT protocols can then be applied and data with greater signal/noise ratio may be obtained.

FIG. 2 f illustrates an embodiment of a system for a coiled tubing downhole injection test (CDIT). CDIT may be applicable to low signal/noise situations introduced by casing conditions. In this test, the pressure gauge is installed on a resettable packer deployed by coiled tubing with a pressure gauge. A CPIT, CRIT and/or FPT are then performed using a surface pump.

FIG. 2 f depicts a typical well 110 configured for CDIT. In particular, a well 110 may include without limitation, surface casing 111, production casing 113, and surface valves 117. However, embodiments of the system 100 also may be used in uncased (openhole completed) wells. The downhole assembly 193 is deployed on coiled tubing 190 and set in position above the perforations 118. The surface pump 191 injects fluid into the formation 119 while the pressure gauge 195 measures the pressure. FIG. 2 f shows a well 110 with a first formation 119. Other components of a well are not shown and are well known in the art.

Still referring to FIG. 2 f, the corrections necessary to obtain sandface volume and pressure may be reduced by using coiled tubing 190 to carry the injected fluid from a surface metering pump 191. The downhole assembly 193, including the pressure gauge 195, can be lowered on coiled tubing 190 and the packing 194 set above the perforations 118 and formation 119 of interest. The CPIT, CRIT or FPT protocols can then be applied and data with greater signal/noise ratio may be obtained.

FIG. 8 shows an example of staged testing of a well in accordance with various embodiments. In FIG. 8, the well is perforated at 802. After perforation, the observed pressure (surface pressure in FIG. 8) builds due to influx of water into the wellbore from the formation. At 804, about 10 gallons of water are injected from the surface. The injection causes the observed pressure to increase, and the decline in pressure at 812 indicates that the liquid is being injected into the formation. Additional injection stages are performed at 806, 808, and 810. Thus, in the example of FIG. 8, using the method of FIG. 7, well data may be acquired in five stages—a production stage after perforation, and four subsequent injection stages. As explained above, the amount of fluid injected into the formations is relatively small (e.g., less than 45 gallons in FIG. 8) and the test execution time is relatively short (less than 2 hours in FIG. 8). Accordingly, embodiments of the well testing method 700 can significantly reduce the time and cost associated with determining flow properties of a reservoir.

FIG. 9 shows conversion of the raw data acquired in FIG. 8 to sandface rate and pressure in accordance with various embodiments. Sandface rate and pressure may be analyzed using the baseline/calibration method or other analysis methods.

FIG. 3 illustrates, according to an example of an embodiment computer system 20, which performs the operations described in this specification to analyze and process the pressure date and flow data to determine the reservoir pressure, and perform other operations disclosed herein. In this example, system 20 is as realized by way of a computer system including workstation 21 connected to server 30 by way of a network. Of course, the particular architecture and construction of a computer system useful in connection with this invention can vary widely. For example, system 20 may be realized by a single physical computer, such as a conventional workstation or personal computer, or alternatively by a computer system implemented in a distributed manner over multiple physical computers. Accordingly, the generalized architecture illustrated in FIG. 3 is provided merely by way of example.

As shown in FIG. 3 and as mentioned above, system 20 may include workstation 21 and server 30. Workstation 21 includes central processing unit 25, coupled to system bus. Also coupled to system bus BUS is input/output interface 22, which refers to those interface resources by way of which peripheral functions P (e.g., keyboard, mouse, display, etc.) interface with the other constituents of workstation 21. Central processing unit 25 refers to the data processing capability of workstation 21, and as such may be implemented by one or more CPU cores, co-processing circuitry, and the like. The particular construction and capability of central processing unit 25 is selected according to the application needs of workstation 21, such needs including, at a minimum, the carrying out of the functions described in this specification, and also including such other functions as may be executed by computer system. In the architecture of allocation system 20 according to this example, system memory 24 is coupled to system bus BUS, and provides memory resources of the desired type useful as data memory for storing input data and the results of processing executed by central processing unit 25, as well as program memory for storing the computer instructions to be executed by central processing unit 25 in carrying out those functions. Of course, this memory arrangement is only an example, it being understood that system memory 24 may implement such data memory and program memory in separate physical memory resources, or distributed in whole or in part outside of workstation 21. In addition, as shown in FIG. 2, measurement inputs 28 that are acquired from laboratory or field tests and measurements are input via input/output function 22, and stored in a memory resource accessible to workstation 21, either locally or via network interface 26.

Network interface 26 of workstation 21 is a conventional interface or adapter by way of which workstation 21 accesses network resources on a network. As shown in FIG. 2, the network resources to which workstation 21 has access via network interface 26 includes server 30, which resides on a local area network, or a wide-area network such as an intranet, a virtual private network, or over the Internet, and which is accessible to workstation 21 by way of one of those network arrangements and by corresponding wired or wireless (or both) communication facilities. In this embodiment of the invention, server 30 is a computer system, of a conventional architecture similar, in a general sense, to that of workstation 21, and as such includes one or more central processing units, system buses, and memory resources, network interface functions, and the like. According to this embodiment of the invention, server 30 is coupled to program memory 34, which is a computer-readable medium that stores executable computer program instructions, according to which the operations described in this specification are carried out by allocation system 30. In this embodiment of the invention, these computer program instructions are executed by server 30, for example in the form of a “web-based” application, upon input data communicated from workstation 21, to create output data and results that are communicated to workstation 21 for display or output by peripherals P in a form useful to the human user of workstation 21. In addition, library 32 is also available to server 30 (and perhaps workstation 21 over the local area or wide area network), and stores such archival or reference information as may be useful in allocation system 20. Library 32 may reside on another local area network, or alternatively be accessible via the Internet or some other wide area network. It is contemplated that library 32 may also be accessible to other associated computers in the overall network.

Of course, the particular memory resource or location at which the measurements, library 32, and program memory 34 physically reside can be implemented in various locations accessible to allocation system 20. For example, these data and program instructions may be stored in local memory resources within workstation 21, within server 30, or in network-accessible memory resources to these functions. In addition, each of these data and program memory resources can itself be distributed among multiple locations. It is contemplated that those skilled in the art will be readily able to implement the storage and retrieval of the applicable measurements, models, and other information useful in connection with this embodiment of the invention, in a suitable manner for each particular application.

According to this embodiment, by way of example, system memory 24 and program memory 34 store computer instructions executable by central processing unit 25 and server 30, respectively, to carry out the functions described in this specification, by way of which an estimate of the allocation of gas production among multiple formations can be generated. These computer instructions may be in the form of one or more executable programs, or in the form of source code or higher-level code from which one or more executable programs are derived, assembled, interpreted or compiled. Any one of a number of computer languages or protocols may be used, depending on the manner in which the desired operations are to be carried out. For example, these computer instructions may be written in a conventional high level language, either as a conventional linear computer program or arranged for execution in an object-oriented manner. These instructions may also be embedded within a higher-level application. For example, an executable web-based application can reside at program memory 34, accessible to server 30 and client computer systems such as workstation 21, receive inputs from the client system in the form of a spreadsheet, execute algorithms modules at a web server, and provide output to the client system in some convenient display or printed form. It is contemplated that those skilled in the art having reference to this description will be readily able to realize, without undue experimentation, this embodiment of the invention in a suitable manner for the desired installations. Alternatively, these computer-executable software instructions may be resident elsewhere on the local area network or wide area network, or downloadable from higher-level servers or locations, by way of encoded information on an electromagnetic carrier signal via some network interface or input/output device. The computer-executable software instructions may have originally been stored on a removable or other non-volatile computer-readable storage medium (e.g., a DVD disk, flash memory, or the like), or downloadable as encoded information on an electromagnetic carrier signal, in the form of a software package from which the computer-executable software instructions were installed by allocation system 20 in the conventional manner for software installation.

In general, embodiments of the methods may be performed before any significant injection or withdrawal of fluids in order to reduce the scale of supercharging. Consequently, the method may be applied to newly drilled wells before any pumping or stimulation activity. However, in low permeability reservoirs such as shales the test method may be performed post hydraulic fracture or after creating a hydraulic fracture as part of the testing procedure to increase the reservoir area contacted. A hydraulic fracture (i.e., formation breakdown) may also be performed if due to damage or other reasons the perforations or open hole section is not properly connected to the main reservoir interval that desired to be tested. In such embodiments, providing adequate relaxation time to allow the effect of supercharging to dissipate maybe necessary and/or performing three or more injection test periods to collect data needed to correct for supercharging. In some cases where reservoir fluid has entered the wellbore prior to the injection test depletion may need to be corrected for and/or sufficient time allowed prior to the injection test to allow for the reservoir to local recharge near the wellbore region.

It is possible that a number of other reservoir properties can be estimated using the same baseline and calibration trends determined by the disclosed method, including permeability-height and water relative permeability endpoint, among others. Permeability-height is related to the slope of the baseline and calibration trends. The permeability relationships determined from these injection tests are related to the fluid being injected. Where the injected fluid is water, permeability to water or Kw is inferred. If fluid saturations within the sampled region or either known or can be reasonably assumed, there is the possibility that the water relative permeability endpoint can be extracted from the injection test data. This combined with data and analysis from currently used injection testing methods (e.g., Diagnostic Fracture Injection Test (DFIT), Mini Fall-off (MFO), Injection Fall-off Test (IFoT) where relative permeability to gas might be determined could result in endpoints for relative permeability curve estimates. Operationally, these currently used injection testing methods would be executed after the baseline/calibration test protocol described in this document. As an example, a CPIT could be conducted followed by an IFoT. The advantages would be to obtain independent estimates of reservoir pressure and possibly an improved understanding of reservoir relative permeability. Obtaining meaningful data from the IFoT requires reaching the pseudo radial flow period and could also require the running of a downhole pressure gauge both of which could cause unacceptable operational delays. Therefore, while desirable to run both types of test operational limitations may prohibit running the IFoT. Advantages of the CPIT vs. the IFoT would include potentially requiring less time, being more economical and not requiring the running of any downhole equipment thus reducing operational risk.

While the embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described and the examples provided herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims.

The discussion of a reference is not an admission that it is prior art to the present invention, especially any reference that may have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated herein by reference in their entirety, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein. 

What is claimed is:
 1. A method for testing a reservoir, comprising: causing a volume of liquid to be injected into or produced out of the reservoir, wherein the reservoir is accessed via a well and the reservoir has not been stimulated; measuring one or more parameters indicative of flow properties of the reservoir over a first predetermined period of time to form a first stage dataset, wherein the one or more parameters includes pressure; inducing a change in an injection rate, a production rate, an injection pressure, or a production pressure of the liquid into or out of the reservoir; measuring the one or more parameters indicative of flow properties for at least a second predetermined period of time to form a second stage dataset; determining sandface rate and pressure based on the first stage dataset and the second stage dataset.
 2. The method of claim 1, wherein: the first predetermined period of time is no more than 30 minutes and the second predetermined time is no more than 30 minutes; or the first predetermined period of time is no more than 10 minutes and the second predetermined time is no more than 10 minutes.
 3. The method of claim 1, wherein the change in rate comprises a change in injection rate or a change in production rate, and the change in pressure comprises a change in injection pressure or a change in production pressure.
 4. The method of claim 1, further comprising, after forming the second stage dataset, performing iterations of: inducing a change in the injection rate, the production rate, the injection pressure, or the production pressure of the liquid into or out of the reservoir; measuring the one or more parameters indicative of flow properties for at least a predefined period of time to form an iteration stage dataset; and after a final one of the iterations: performing the determining based on each iteration stage dataset.
 5. The method of claim 1, wherein the volume of liquid is no more than 40 gallons.
 6. The method of claim 1, further comprising selecting a rate of injection for the liquid to prevent fracturing of formations of the reservoir during the testing.
 7. The method of claim 1, wherein the determining comprises correcting for ballooning of wellbore casing and weepage of the wellbore casing due to an increase in pressure caused by the testing.
 8. A method for testing a reservoir, comprising: in a first stage: injecting into, or producing from, the reservoir a liquid at a first rate or first pressure and measuring one or more parameters indicative of flow properties of the reservoir over a first time period to form a first stage dataset; in one or more additional stages: injecting into, or producing from, the reservoir a liquid at a given rate or given pressure and measuring the one or more parameters indicative of flow properties of the reservoir over a given time period to form one or more additional stage datasets, wherein the given rate is different from the first rate, and the given pressure is different from the first pressure; and determining sandface rate and pressure based on the first stage dataset and the one or more additional stage datasets.
 9. The method of claim 8, wherein a total time spent in the first stage and additional stages is no more than 12 hours.
 10. The method of claim 8, wherein each of the first time period and the each given time period is between 10 and 30 minutes.
 11. The method of claim 8, wherein a volume of the liquid injected in each of the first stage and each of the additional stages is between 10 and 40 gallons.
 12. The method of claim 8, further comprising selecting the first rate and additional rate to prevent fracturing of formations of the reservoir during the testing.
 13. The method of claim 8, wherein the determining comprises correcting for ballooning of wellbore casing and weepage of the wellbore casing due to an increase in pressure caused by the testing.
 14. A system for testing a reservoir, comprising: one or more sensors configured to measure parameters indicative of flow properties of the reservoir, wherein the one or more parameters comprise pressure, and the reservoir has not been stimulated; a pump configured to deliver liquid in a wellbore, the wellbore fluidically coupled to the reservoir; a controller configured to: cause the pump to inject a volume of liquid into the reservoir; cause the sensors to measure one or more parameters indicative of flow properties of the reservoir over a first predetermined period of time to form a first stage dataset, wherein the one or more parameters includes pressure; cause the pump to change a rate or pressure of injection of the liquid into the reservoir after completion of the first stage dataset; cause the sensors to measure the one or more parameters indicative of flow properties for at least a second predetermined period of time to form a second stage dataset; a processing unit configured to process the first stage dataset and the second stage dataset to determine sandface rate and pressure.
 15. The system of claim 15 wherein the pump is a surface pump, and further comprising a length of coiled tubing coupled to the pump and running into the wellbore.
 16. The system of claim 15, wherein the pump is a downhole pump, and further comprising a wireline or a length of coiled tubing coupled to the pump to deploy the pump in the wellbore.
 17. The system of claim 15 wherein the sensors comprise one or more of a pressure sensor, an acoustic sensor, and a fluid level sensor.
 18. The system of claim 15, wherein the controller is configured to: set the first predetermined period of time to be no more than 30 minutes and the second predetermined time to be no more than 30 minutes; or set the first predetermined period of time to be no more than 10 minutes and the second predetermined time to be no more than 10 minutes.
 19. The system of claim 15, wherein the controller is configured to inject the liquid at rate that prevents fracturing of formations of the reservoir during the testing.
 20. The system of claim 15, wherein the processing unit is configured to correct for ballooning of wellbore casing and weepage of the wellbore casing due to an increase in pressure caused by the injection of liquid during the testing. 